This disclosure relates in general to drilling a borehole using a drilling fluid and, more specifically, but not by way of limitation, to detecting, measuring and/or controlling influxes of formation water and/or brine into the borehole.
To access a subsurface hydrocarbon reservoir, it is common practice to drill a hole, generally referred to as a borehole or wellbore, through intervening rock formations using a rotating drill bit at the lower end of a hollow drill pipe. The diameter of the borehole is determined by the diameter of the drill bit, which exceeds the outer diameter of the drill pipe, and, as a result, produces an annulus between the drill pipe and the interior surface of the borehole. In the drilling procedure, rock cuttings produced by the drill bit cutting its way through the earth formation are carried away from the drill bit up to the surface via the annulus by a drilling fluid, which may be a drilling mud or the like, where it is usual to pump the drilling fluid down the hollow drill pipe and back up the annulus when the cuttings are removed and various properties of the fluid may be measured prior to subsequent circulation through the borehole.
Two main types of drilling fluid are commonly used in drilling procedures. In the first type of drilling fluid the external liquid phase is aqueous, i.e., the drilling fluid may comprise a water-based-mud (“WBM”) or the like, and in the second type of drilling fluid the external liquid phase is oleaginous, i.e., the drilling fluid may comprise an oil-based-mud (“OBM”) or the like. For purposes of this specification WBMs and OBMs are provided as examples of drilling fluids, however, the term drilling fluid(s) may encompass other types of materials, fluids and/or the like.
The oleaginous external, or continuous, phase of OBM is typically kerosene or a similar light liquid hydrocarbon in which is dissolved various oil-soluble surfactants. The internal, or dispersed, phase of OBM typically comprises: (a) an oleophilic clay to impart the desired rheology to the mud; (b) a dense mineral, such as barite, to impart the desired density to the mud; and (c) an emulsified-aqueous brine to impart the desired water activity to the mud. In use, the OBM accumulates formation fines or solids, where the fines and/or solids are circulated through the annulus with the OBM, pass through a shale-shaker and re-enter the circulated OBM. Oil-soluble surfactants may be used with the OBM to prevent agglomeration of mineral particles, such as barite and formation fines, and to emulsify the emulsified-aqueous brine to provide a stable water-in-oil emulsion. By altering the salt concentration in the brine, the water activity of the mud can be changed so that it approximates that of the formation being drilled, which serves to prevent instability of the borehole being drilled due to the welling or shrinking of shale and compacted clay formations surrounding the borehole.
In OBM supplied to a drilling rig, the oil-soluble surfactants in the OBM are in excess of the amounts required for effective use of the OBM in a drilling procedure. The excess amount of the oil-soluble surfactants may be provided so that extra solids and aqueous liquids that may be acquired by the mud while drilling can be effectively dispersed in the mud. The acquisition rate of solids and aqueous liquids by the mud is usually determined by the penetration rate of the bit. However, a problem may occur when a water or brine influx into the borehole occurs from freshwater or brine aquifers encountered during the drilling process. Such influxes can add aqueous liquid rapidly to the OBM.
Owing to the excess emulsifier present in the OBM, influxes of freshwater or brine become emulsified and add to the existing aqueous phase already present in the OBM and have undesirable effects on several of the mud's parameters, e.g. rheology, density, fluid loss, and water activity. Of particular relevance is the effect of the influx on the American Petroleum Institute (“API”)/Emulsion Stability Test (“EST”), which is routinely used during the drilling process to monitor the mud. The influx of fresh or saline water acts to decrease the EST breakdown voltage (“VBD”), which results in a misleading measure of the emulsion stability. Moreover, the API EST comprises application of high voltages (typically 500V to 1500V) to a probe placed in the drilling fluid to cause an electrical breakdown, which may be hazardous in the presence of gaseous hydrocarbons.
The probe for the API EST consists of two planar electrodes, ⅛ inch in diameter, facing each other 1/16 inch apart, which arrangement requires manual cleaning of mud from the probe between tests and, hence, is not designed nor easily modified for continuous or automatic operation on a drilling rig and/or in a remote drilling environment. These problems with the API EST as well as the danger of the high voltage necessary for the probes use may be overcome by using an embodiment of the present invention, as described below.